Method of pumping aqueous fluid containing surface modifying treatment agent into a well

ABSTRACT

A well treatment fluid contains a surface modifying treatment agent having an anchor and a hydrophobic tail. The surface modifying treatment agent is an organophosphorus acid derivative. After the well treatment fluid is pumped into a well penetrating the subterranean formation, the anchor binds to the surface of the formation. The subterranean formation is a siliceous formation or a metal oxide-containing subterranean formation. The anchor bonds to a Si atom when the formation is a siliceous formation and to the metal of the metal oxide when the formation is a metal oxide-containing formation. After being bound to the surface of the formation, frictional drag within the well is reduced. This allows for faster recovery of formation fluids. The bonding of the surface modifying treatment agent onto the formation may further be enhanced by first pre-treating the formation with an aqueous fluid. By increasing the number of sites for the surface modifying treatment agent to bind onto the surface of the subterranean formation, productivity is improved.

This application is a divisional application of U.S. patent applicationSer. No. 14/643,245 which claims the benefit of U.S. Patent PublicationNo. 2015/0083416 (the published application of U.S. patent applicationSer. No. 14/491,772) filed on Sep. 19, 2014 which claims the benefit ofU.S. patent application Ser. No. 61/880,836, filed on Sep. 20, 2013 andU.S. Patent Publication No. 2015/0083417 (the published application ofU.S. patent application Ser. No. 14/491,905) filed on Sep. 19, 2014;both U.S. Patent Publication No. 2015/0083416 and U.S. PatentPublication No. 2015/0083417 further claiming the benefit of U.S. patentapplication Ser. No. 61/880,840 filed on Sep. 20, 2013 and U.S. patentapplication Ser. No. 61/981,051, filed on Apr. 17, 2014 and U.S. patentapplication Ser. No. 61/989,267, filed on May 6, 2014 and U.S. patentapplication Ser. No. 62/007,708, filed on Jun. 4, 2014, all of which areherein incorporated by reference.

FIELD OF THE DISCLOSURE

The disclosure relates to a method of treating a subterranean formationwith a surface modifying treatment agent having an anchor and ahydrophobic tail by pumping into a well an aqueous well treatment fluidcomprising the surface modifying treatment agent.

BACKGROUND OF THE DISCLOSURE

Alternatives for enhancing the productivity of hydrocarbons fromhydrocarbon producing reservoirs have included methods which increasethe permeability of the formation penetrated by the well. Other methodshave been directed to those which increase the oil/water productionratios within the well. Others have been drawn improved methods forinhibiting the formation of undesirable materials in the formationincluding water borne scales, asphaltenes, salts, paraffins, etc. Someof these methods have involved the development of well treatmentchemicals for enhancing productivity.

Attention has further been focused on improving methods of stimulatingformations. Since well productivity depends on the ability of a fractureto conduct hydrocarbons from the formation to the wellbore, fractureconductivity has been an important parameter in determining the degreeof success of a stimulation operation. The creation and/or mobilizationof reservoir “fines” during fracturing and production has beeninstrumental in reducing fracture conductivity and reducing reservoirpermeability due to plugging of pore throats by the fines. While the useof coated particulates, such as proppants, has been successful inminimizing the generation of fines, alternatives have been sought.

Alternatives have also been sought to decrease unnecessary waterproduction during the treatment of subterranean formations. Excessivewater production has a direct effect on the productivity of the well.The amount of oil and/or gas that may be ultimately recovered from thewell is decreased since the water takes the place of other fluids thatmay flow or be lifted from the well. This increases the cost ofproduction from the well.

While well treatment agents have been developed for the treatment orcontrol of the deposition of scales, salts, paraffins, and asphalteneswithin the well, less than desirable results are often achieved.Alternatives have therefore been sought for improving the overallefficiency of the well by controlling the deposition of such materials.Alternatives have especially been sought for controlling the depositionof such materials in low permeability formations, such as shale andcoal.

Resources have also been spent on both chemical and physical techniquesfor effectively reducing frictional drag created during the flow ofhydrocarbons within a hydrocarbon producing reservoir.

Alternatives for reducing friction have focused on drag reductionagents. Typically, friction reduction agents are large polymers withlong chains which tend to build non-Newtonian gel structures. Dragreducing gels are shear-sensitive and often require specializedinjection equipment (such as pressurized delivery systems). Further,since friction reduction agents are typically highly viscous, usually nomore than 10 weight percent of polymeric friction reduction agents arepresent in the carrier fluid. Some attention has been focused on the useof slurries or dispersions of polymers to form free-flowing and pumpablemixtures in liquid media. However, such polymers often agglomerate overtime, thus making it very difficult for them to be placed in hydrocarbonliquids where reduced drag is needed.

Further alternatives for lowering the frictional drag of fluids within awell have been sought in order to enhance the productivity ofhydrocarbons from the well.

Well treatment agents having sites which are reactive with oxides and/orhydroxides of a subterranean formation typically form precipitates whenexposed to water. The formation of such precipitates destroys orseriously weakens the reactive sites of the well treatment agent. It isfor this reason that well treatment agents reactive with oxides and/orhydroxides typically are pumped into a well in a carrier fluid which isnon-aqueous. In addition, such well treatment agents are typicallystored by being formulated in non-aqueous solvents. It is desirable forsuch well treatment agents to be pumped and stored as aqueous fluidswhile maintaining the activity of the well treatment agent.

It should be understood that the above-described discussion is providedfor illustrative purposes only and is not intended to limit the scope orsubject matter of the appended claims or those of any related patentapplication or patent. Thus, none of the appended claims or claims ofany related application or patent should be limited by the abovediscussion or construed to address, include or exclude each or any ofthe above-cited features or disadvantages merely because of the mentionthereof herein.

SUMMARY OF THE DISCLOSURE

In an embodiment of the disclosure, a method of treating a siliceous ormetal oxide-containing subterranean formation is provided. In thisembodiment, an aqueous treatment fluid is prepared which contains asurface modifying treatment agent having an anchor and a hydrophobictail. The surface modifying treatment agent may be pumped into a well inan aqueous media. The aqueous media contains an organic acid. Afterbeing pumped into the well, the surface modifying treatment agent isbound to a surface of the subterranean formation by attaching the anchorto the formation.

In another embodiment of the disclosure, an alternative method oftreating a siliceous or metal oxide-containing subterranean formation isprovided. In this embodiment, an aqueous treatment fluid is pumped intoa well which penetrates the subterranean formation. The treatment fluidcontains a surface modifying treatment agent and an aqueous mediacomprising an organic acid. The surface modifying treatment agent has ananchor and a hydrophobic tail. The surface modifying treatment agent isbound to a surface of the subterranean formation by attaching the anchorto the formation. The surface modifying treatment agent is aligned tothe siliceous or metal oxide-containing subterranean formation such thatthe hydrophobic tail is directed away from the surface of the formation.

In an embodiment of the disclosure, the amount of organic acid in theaqueous media is between from about 0.5 to about 25 volume percent.

In another embodiment, the organic acid of the aqueous media is aceticacid, formic acid, citric acid, oxalic acid, malonic acid, succinicacid, malic acid, tartaric acid, phthalic acidethylenediaminetetraacetic acid (EDTA), nitrilotriacetic acid, glycolicacid, N-hydroxyethyl-N,N′,N′-ethylenediaminetriacetic acid,hydroxyethyliminodiacetic acid, diethylenetriaminepentaacetic acid orcyclohexylenediaminetetraacetic acid or a mixture thereof.

In another embodiment of the disclosure, the anchor of the surfacemodifying treatment agent is a metal and the hydrophobic tail is anorgano-silicon material, a fluorinated hydrocarbon or both anorgano-silicon material and a fluorinated hydrocarbon.

In another embodiment of the disclosure, the anchor of the surfacemodifying treatment agent is an organophosphorus acid derivative and thehydrophobic group is attached to the organophosphorous acid derivative.

Accordingly, the present disclosure relates to an aqueous well treatmentfluid containing a surface modifying treatment agent having ahydrophobic tail and an anchor. The present disclosure further relatesto pumping of the aqueous well treatment fluid into a well penetrating asubterranean formation. In addition, the present disclosure relates toan aqueous medium for storage of the surface modifying treatment agent.

Characteristics and advantages of the present disclosure described aboveand additional features and benefits will be readily apparent to thoseskilled in the art upon consideration of the following detaileddescription of various embodiments and referring to the accompanyingdrawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are part of the present specification, included todemonstrate certain aspects of various embodiments of this disclosureand referenced in the detailed description herein:

FIG. 1 depicts a schematic representation of the attachment of a surfacemodifying treatment agent having a hydrophobic tail and an anchor of anorganophosphorus acid derivative.

FIGS. 2 and 3 depict schematic representations of the attachment of asurface modifying treatment agent having a metallic anchor and ahydrophobic tail to the surface of a subterranean formation.

FIG. 4 illustrates regain permeability in a Berea core by use of asurface modifying treatment agent having a hydrophobic tail and ananchor of an organophosphorus acid derivative.

FIG. 5 illustrates retention in permeability in a synthetic corecontaining 325 mesh silica when using a surface modifying treatmentagent having a hydrophobic tail and an anchor of an organophosphorusacid derivative.

FIG. 6 illustrates the effect of pre-treatment on regain permeability ina Berea core by use of a surface modifying treatment agent having ahydrophobic tail and an anchor of an organophosphorus acid derivative.

FIG. 7 illustrates regain permeability in a Berea core by use of asurface modifying treatment agent having a metallic anchor and ahydrophobic tail.

FIG. 8 demonstrates the inhibition in the swelling of clay using asurface modifying treatment agent having a metallic anchor and ahydrophobic tail.

FIG. 9 demonstrates the lack of movement of fines in a synthetic corecontaining 325 mesh silica when using a surface modifying treatmentagent having a metallic anchor and a hydrophobic tail.

FIG. 10 illustrates the effect of pre-treatment on regain permeabilityin a Berea core by use of a surface modifying treatment agent having ametallic anchor and a hydrophobic tail.

FIGS. 11 and 12 demonstrate the lack of chemical degradation of asurface modifying treatment agent having a metallic anchor andfluorinated hydrophobic tail in an aqueous mixture containing aceticacid.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Characteristics and advantages of the present disclosure and additionalfeatures and benefits will be readily apparent to those skilled in theart upon consideration of the following detailed description ofexemplary embodiments of the present disclosure and referring to theaccompanying figures. It should be understood that the descriptionherein and appended drawings, being of example embodiments, are notintended to limit the claims of this patent or any patent or patentapplication claiming priority hereto. On the contrary, the intention isto cover all modifications, equivalents and alternatives falling withinthe spirit and scope of the claims. Many changes may be made to theparticular embodiments and details disclosed herein without departingfrom such spirit and scope.

Certain terms are used herein and in the appended claims may refer toparticular components, process steps or well treatment operations. Asone skilled in the art will appreciate, different persons may refer to acomponent, a process step or a well treatment operation by differentnames. This document does not intend to distinguish between components,process steps or well treatment operations that differ in name but notfunction or operation. Also, the terms “including” and “comprising” areused herein and in the appended claims in an open-ended fashion, andthus should be interpreted to mean “including, but not limited to . . ..” Further, reference herein and in the appended claims to componentsand aspects in a singular tense does not necessarily limit the presentdisclosure or appended claims to only one such component or aspect, butshould be interpreted generally to mean one or more, as may be suitableand desirable in each particular instance.

A surface modifying treatment agent having an anchor and a hydrophobictail may be pumped into a well in an aqueous fluid. The aqueous fluidcontains an organic acid. The well treatment fluid containing thesurface modifying treatment agent may be prepared by combining thesurface modifying treatment agent with an aqueous media containing theorganic acid.

The organic acid of the aqueous treatment fluid is preferably a weakorganic acid such as acetic acid, formic acid, citric acid, oxalic acid,malonic acid, succinic acid, malic acid, tartaric acid, phthalic acidethylenediaminetetraacetic acid (EDTA), nitrilotriacetic acid, glycolicacid, N-hydroxyethyl-N,N′,N′-ethylenediaminetriacetic acid,hydroxyethyliminodiacetic acid, diethylenetriaminepentaacetic acid,cyclohexylenediaminetetraacetic acid or a mixture thereof. In apreferred embodiment, the organic acid of the aqueous media is selectedfrom the group consisting of acetic acid, formic acid, citric acid andmixtures thereof.

Typically, the amount of organic acid in the aqueous media is betweenfrom about 0.5 to about 25 volume percent.

The surface modifying treatment agent is pumped into the formation as acomponent of an aqueous treatment fluid. The aqueous well treatmentfluid may be prepared on the fly. The aqueous treatment fluid may bepumped into the formation any time during the well treatment operation.In an embodiment, the aqueous well treatment fluid may be a fracturingfluid, pad fluid, acidizing fluid, etc.

The concentration of the surface modifying treatment agent in theaqueous well treatment fluid is typically between from about 0.01% to100% or more typically between from about 0.1% to about 20% (v/v).

The surface modifying treatment agent comprises an anchor and ahydrophobic tail. For purposes herein, the term “hydrophobic tail” shallrefer to the hydrophobic substituent of the surface modifying treatmentagent. The “anchor” refers to the non-hydrophobic portion of the surfacemodifying treatment agent derivative. The anchor provides the site ofattachment of the surface modifying treatment agent onto thesubterranean formation. For instance, the anchor may be engaged incovalently connecting the surface modifying treatment agent to a surfaceof the subterranean formation.

The hydrophobic tail may be directly attached to the anchor.Alternatively, the hydrophobic tail may be indirectly attached to theanchor such that an organo-functional group is between the anchor andthe hydrophobic tail. For instance, the hydrophobic tail and the anchormay be separated by a hydrocarbyl group such as a saturated orunsaturated alkylene, alkenyl, alkynyl, etc.

While the tail of the treatment agent exhibits hydrophobiccharacteristics, it may also exhibit oleophobic properties. Thetreatment agent may therefore be considered to be omniphobic.

The hydrophobic tail of the surface modifying treatment agent is notbelieved to bind to the subterranean substrate. The tail of the surfacemodifying treatment agent is only indirectly attached to the formationsubstrate, through the anchor.

In an embodiment, the tail of the surface modifying treatment agentself-aligns with the formation substrate to form a monolayer ormulti-layer assembly. It is believed that this occurs by chemicalbinding-induced spontaneous organization of the tail on the substratesurface. The tail of the surface modifying treatment agent may bealigned such that the hydrophobicity character of the treatment agent isimparted away from the surface of the subterranean formation. In apreferred embodiment, the tail may self-align to the surface of thesiliceous or metal oxide containing formation such that thehydrophobic/omniphobic tail is opposite to the surface of the formation.

The surface modifying treatment agent, when bound to a surface of asubstrate, reduces friction of a fluid within the well. Water and thusaqueous fluids within the well may easily slide across the surface ofthe substrate carrying hydrocarbons with it as lateral adhesion of thefluid to the formation surface is reduced. Thus, the hydrophobic taillowers water saturation and enhances recovery of water from theformation surface.

The subterranean formation, onto which the surface modifying treatmentagent is bond, may be a siliceous formation, such as sandstone, as wellas a metal oxide containing formation, including carbonate formations.The formation may be enriched in clay and the metal may include alumina.

In a preferred embodiment, the anchor of the surface modifying treatmentagent may be an organophosphorus acid derivative with the hydrophobicgroup attached to the anchor. In another preferred embodiment, theanchor of the surface modifying treatment agent may be a metal and thehydrophobic tail may be an organo-silicon material, a fluorinatedhydrocarbon or both an organo-silicon material and a fluorinatedhydrocarbon.

Organophosphorus as Anchor

The organophosphorus acid derivative comprising the anchor of thesurface modifying treatment agent may originate from an organophosphoricacid, organophosphonic acid or organophosphinic acid. The organo groupsof the anchor may be monomeric or polymeric.

Examples of monomeric phosphoric acid derivatives are compounds ormixtures of compounds having the structure (RO)_(x)—P(O)—(OR′)_(y)wherein x is 1-2, y is 1-2 and x+y=3; R preferably is a radical having atotal of 1-30, preferably 2-20, more preferably 6-18 carbons; R′ is H, ametal such as an alkali metal, for example, sodium or potassium or loweralkyl having 1 to 4 carbons, such as methyl or ethyl. Preferably, aportion of R′ is H. The organic component of the phosphoric acid (R) canbe a saturated or unsaturated aliphatic group or can be an aryl oraryl-substituted moiety. At least one of the organo groups can containterminal or omega functional groups as described below.

Examples of monomeric phosphonic acid derivatives include compounds ormixtures of compounds having the formula:

wherein a is 0-1, b is 1, c is 1-2 and a+b+c is 3; R and R″ preferablyare each independently a radical having a total of 1-30, preferably2-20, more preferably 6-18 carbons; R′ is H, a metal, such as an alkalimetal, for example, sodium or potassium or lower alkyl having 1-4carbons such as methyl or ethyl. Preferably at least a portion of R′ isH. The organic component of the phosphonic acid (R and R″) can be asaturated or unsaturated aliphatic group or an aryl or aryl-substitutedmoiety. At least one of the organo groups can contain terminal or omegafunctional groups as described below.

Examples of monomeric phosphinic acid derivatives are compounds ormixtures of compounds having the formula:

wherein d is 0-2, e is 0-2, f is 1 and d+e+f is 3; R and R″ preferablyare each independently radicals having a total of 1-30, preferably 2-20carbons atoms, more preferably 6-18 carbons; R′ is H, a metal, such asan alkali metal, for example, sodium or potassium or lower alkyl having1-4 carbons, such as methyl or ethyl. Preferably a portion of R′ is H.The organic component of the phosphinic acid (R, R″) can be a saturatedor unsaturated aliphatic group or be an aryl or aryl-substituted moiety.Examples of organo groups which may comprise R and R″ include long andshort chain aliphatic hydrocarbons, aromatic hydrocarbons andsubstituted aliphatic hydrocarbons and substituted aromatichydrocarbons.

At least one of the organo groups can further contain one or moreterminal or omega functional groups which are hydrophobic. Examples ofterminal or omega functional groups include carboxyl such as carboxylicacid, hydroxyl, amino, imino, amido, thio and phosphonic acid, cyano,sulfonate, carbonate and mixed substituents.

Representative of organophosphorus acid derivatives are aminotrismethylene phosphonic acid, aminobenzylphosphonic acid, 3-aminopropyl phosphonic acid, O-aminophenyl phosphonic acid, 4-methoxyphenylphosphonic acid, aminophenylphosphonic acid, aminophosphonobutyric acid,aminopropylphosphonic acid, benzhydrylphosphonic acid, benzylphosphonicacid, butylphosphonic acid, carboxyethylphosphonic acid,diphenylphosphinic acid, dodecylphosphonic acid, ethylidenediphosphonicacid, heptadecylphosphonic acid, methylbenzylphosphonic acid,naphthylmethylphosphonic acid, octadecylphosphonic acid, octylphosphonicacid, pentylphosphonic acid, phenylphosphinic acid, phenylphosphonicacid, styrene phosphonic acid, and dodecyl bis-1,12-phosphonic acid.

In addition to monomeric organophosphorus acid derivatives, oligomericor polymeric organophosphorus acid derivatives resulting fromself-condensation of the respective monomeric acids may be used.

In a preferred embodiment, the surface modifying treatment agent is ofthe formula R_(f)—(CH₂)_(p)—Z where Z, the anchor is H, F or an acidderivative, and the hydrophobic tail (bonded to the anchor) is afluorine containing moiety, such as R_(f)—(CH₂)_(p)— where R_(f) is aperfluorinated alkyl group or a perfluorinated alkylene ether group andp is 2 to 4, preferably 2.

Typically, the fluorine containing moiety has a number average molecularweight of less than 2000.

Examples of perfluorinated groups for the fluorine containing moiety arethose of the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6.

A preferred oligomeric or perfluoroalkylene ether group is where Rand/or R″ is a group of the structure:

where A is an oxygen radical or a chemical bond such as CF₂; n is 1 to20, preferably 1 to 6; Y is H, F, C_(n)H_(2n+1) or C_(n)F_(2n+1); b isat least 1, preferably 2 to 10, m is 0 to 50, and p is 1 to 20.

In an embodiment, the surface modifying treatment agent is of theformula R_(f)—(CH₂)_(p)—Z, wherein Z is:

where R and R″ are a hydrocarbon or substituted hydrocarbon radicalhaving up to 200, such as 1 to 30 and 6 to 20 carbons, R and R″ can alsoinclude the perfluoroalkyl groups mentioned above, and R′ is H, a metalsuch as potassium or sodium or an amine or an aliphatic radical, forexample, alkyl including substituted alkyl having 1 to 50 carbons,preferably lower alkyl having 1 to 4 carbons such as methyl or ethyl, oraryl including substituted aryl having 6 to 50 carbons.

In an embodiment, the surface modifying treatment agent is of theformula CF₃(C_(n)F_(2n))CH₂CH₂PO₃H₂ where n is between 3 and 5 orCF₃(CF₂)_(x)O(CF₂CF₂)_(y)—CH₂CH₂—PO₃H₂ where x is from 0 to 7, y is from1 to 20 and x+y is less than or equal to 27.

Where the surface modifying treatment agent contains an organophosphorusacid derivative and without being bound to any theory, it is believedthat upon being pumped into the formation, a silicon atom of thesiliceous subterranean formation covalently interacts with the anchor ofthe surface modifying treatment agent to form a Si—O—P covalent bridge.The bridges are believed to result from the condensation of hydroxylgroups on the surface of the formation with P—OH groups. Thus, exemplarybonding of the anchor and the surface of the substrate formation may berepresented as —O—P—O—Si—. The hydrophobic tail of the surface modifyingtreatment agent is thus attached to the siliceous formation through theintermediary —O—P—O bond. The anchor of the surface modifying treatmentagent thus forms a covalent bond with the hydroxyl reactive group on thesurface of the siliceous formation. A complexation of the phosphoryloxygen surface X atom is believed to form.

Upon being pumped into a metal oxide-containing formation, the anchor ofthe surface modifying treatment agent having an organophosphorus acidderivative is believed to covalently interact with a metal atom (“M”) ofthe metal oxide surface of the subterranean formation to form a M-O—Pcovalent bridge. The bridges are believed to result from thecondensation of hydroxyl groups on the surface of the formation withP—OH groups. Thus, exemplary bonding of the anchor and the surface ofthe substrate formation may be represented as —O—P—O-M-. The hydrophobictail of the surface modifying treatment agent is thus attached to themetal oxide-containing formation through the intermediary —O—P—O bond.The anchor of the surface modifying treatment agent thus forms acovalent bond with the oxide reactive group on the surface of theformation. A complexation of the phosphoryl oxygen surface metal atom isbelieved to form.

FIG. 1 depicts a schematic representation of the formation of atridentate phosphonate surface species by coordination and condensationto the surface of a formation, wherein X is either —Si (of a siliceousformation) or -M (of a metal oxide-containing formation).

Organo-Silicon and/or Fluorinated Hydrocarbon as Anchor

In an embodiment, the surface modifying treatment agent contains a metallinked to an organo-silicon containing material or a fluorinatedhydrocarbon.

The anchor of the surface modifying treatment agent may be a metal. Forinstance, the anchor may be a Group 3, 4, 5, or 6 metal. In a preferredembodiment, the metal is a Group 4 metal, such as Ti, Zr or Hf, a Group5 metal, such as Ta or Nb, a Group 6 metal, such as W, or a metal of thelanthanide series, such as La.

The hydrophobic tail of the surface modifying treatment agent may be anorgano-silicon material, a fluorinated hydrocarbon or both a hydrophobicorgano-silicon material and a fluorinated hydrocarbon.

The surface modifying treatment agent may be represented by the formulaJ-K, wherein K is the metallic anchor (such as that represented by ametal containing organic ligand) and J is the hydrophobic tailrepresented by the organo-silicon containing material, the fluorinatedhydrocarbon or a combination of organo-silicon containing material andfluorinated hydrocarbon.

While not being bound to any theory, it is believed that upon beingpumped into the formation, the metal of the surface modifying treatmentagent covalently binds to the formation. The formation may be asiliceous formation or a metal oxide containing formation, includingcarbonate formations. The metal oxide containing formation may bealumina. The metal may therefore be referred to as the “anchor” of thesurface modifying treatment agent, a site that engages in covalentlyconnecting the treatment agent to the surface of the formation. It isbelieved that the metal of the surface modifying treatment agent bindsto the oxygen atom of the silicon-oxo or the metal-oxo linkage of theformation.

FIG. 2 and FIG. 3 depict schematic representations of the attachment ofthe surface modifying treatment agent onto the substrate wherein Z isthe metal of the anchor, J is the hydrophobic tail and Y is either —Si(of a siliceous formation) or the metal (M) (of a metal oxide-containingformation). In FIG. 2, the surface of the formation contains a free —OHwhich may, for example, be attached to an aluminum atom or a siliconatom. As illustrated, the metal of the surface modifying treatment agentmay bind to the oxygen atom of the silicon-oxo or the aluminum-oxolinkage of the substrate by reaction with the —OH group. In FIG. 3, thesurface of the formation is shown as containing a silicon-oxo groupwithout a free —OH. The mechanism of reaction of the surface modifyingtreatment agent is illustrated as being different from that set forth inFIG. 3.

The organo-silicon or fluorinated hydrocarbon portion of the surfacemodifying agent is attached to the metal forming the anchor and is notbelieved to bind to the subterranean substrate. It is therefore referredto as the “tail” portion of the surface modifying treatment agent. Thus,the tail of the surface modifying treatment agent is only indirectlyattached to the formation substrate, through the metal.

The tail of the surface modifying treatment agent may be aligned suchthat the hydrophobicity character of the treatment agent is impartedaway from the anchor.

The surface modifying treatment agent may be formed by reacting a metalcontaining organic ligand with the organo-silicon containing materialand/or fluorinated hydrocarbon group.

The metal containing organic ligand may be formed by reacting a metalcompound, such as a metal halide, like TaCl₅, with an oxygen containingligand. The number of oxygen containing ligands attached to the metal istypically equal to the valency of the metal atom. Thus, depending uponthe position of the transition metal on the Periodic Chart, the metalcontaining organic ligand may have from two to six organic ligandgroups.

In an embodiment, the ligand of the metal containing organic ligandcontains an alkoxide or ester. Suitable organometallic derivativesinclude metal derivatives of C₁ to C₁₈ alkoxides, preferably alkoxidescontaining from 2 to 8 carbon atoms such as ethoxide, propoxide,isopropoxide, butoxide, isobutoxide and tertiary butoxide. For instance,the metal containing organic ligand may be a transition metaltetra-alkoxide, such as zirconium tetra tert-butoxide.

The alkoxides may be in the form of simple esters and polymeric forms ofthe alkoxylates and esters as well as various chelates and complexes.For example, with the metal Ta, the simple esters could be Ta(OR)₅ whereR is C₁ to C₁₈ alkyl. Polymeric esters may be obtained by condensationof an alkyl ester and can have the structure RO—[Ta(OR)₃—O-]_(x)—R whereR is defined above and x is a positive integer.

Further, the organometallic compound can include, for instance, when themetal is titanium or zirconium:

(a) alkoxylates having the general formula M(OR)₄, wherein M is selectedfrom Ti and Zr and R is C₁₋₁₈ alkyl;

(b) polymeric alkyl titanates and zirconates obtainable by condensationof the alkoxylates of (a), i.e., partially hydrolyzed alkoxylates of thegeneral formula RO[-M(OR)₂O-]_(x-1)R, wherein M and R are as above and xis a positive integer;

(c) titanium chelates, derived from ortho titanic acid andpolyfunctional alcohols containing one or more additional hydroxyl,halo, keto, carboxyl or amino groups capable of donating electrons totitanium. Examples of these chelates are those having the generalformula Ti(O)_(a)(OH)_(b)(OR′)_(c)(XY)_(d), wherein a=4-b-c-d;b=4-a-c-d; c=4-a-b-d; d=4-a-b-c; R′ is H, R as above or X-Y, wherein Xis an electron donating group such as oxygen or nitrogen and Y is analiphatic radical having a two or three carbon atom chain such as:

-   -   (i) —CH₂CH₂—, e.g., of ethanolamine, diethanolamine and        triethanolamine, or

-   -   (ii) lactic acid,

-   -   (iii) acetylacetone enol form, and

-   -   (iv) 1,3-octyleneglycol,

(d) titanium acrylates having the general formula Ti(OCOR)_(4-n)(OR)_(n)wherein R is C₁₋₁₈ alkyl as above and n is an integer of from 1 to 3,and polymeric forms thereof, or

(e) mixtures thereof.

Acetyl acetonates, alkanolamines, lactates and halides, such aschloride, can also be used as the ligand of the oxygen containingorganic ligand. In addition, the oxygen containing ligand can contain amixture of ligands selected alkoxides, acetyl acetonates, alkanolamines,lactates and halides.

In an embodiment, the organo-silicon containing material may be asilane, polysiloxane or a polysilazane.

Examples of organo-silicon containing materials are those having theformula R¹ _(4-x)SiA_(x) or (R¹ ₃Si)_(y)B as well asorgano(poly)siloxanes and organo(poly)silazanes containing units of theformula:

where R¹ may be the same or different and is a hydrocarbon radicalcontaining from 1 to 100, such as 1 to 20 carbon atoms and 1 to 12,preferably 1 to 6 carbon atoms and R³ may be hydrogen or a hydrocarbonor substituted hydrocarbon having 1 to 12, preferably 1 to 6 carbonatoms. In addition, R¹ may be a substituted, hydrocarbon radical such ashalo, particularly a fluoro-substituted hydrocarbon radical. Theorgano(poly)siloxane may further contain additional units of theformula: R⁵ ₂SiO₂ where R⁵ is a halogen such as a chloro or fluorosubstituent.

In an embodiment, the organo-silicon containing compound may be anorgano(poly)siloxane or organo(poly)silazane of a number averagemolecular weight of at least 400, usually between 1000 and 5,000,000.

The substituent A in R¹ _(4-x)SiA_(x) may be hydrogen, a halogen such aschloride, OH, OR² or

wherein B in the above structural formula may be NR³ _(3-y), R² ahydrocarbon or substituted hydrocarbon radical containing from 1 to 12,typically 1 to 4 carbon atoms. R³ is hydrogen or has the same meaning asR¹, x is 1, 2 or 3, y is 1 or 2.

Preferably, R¹ is a fluoro-substituted hydrocarbon. Preferred are suchfluoro-substituted hydrocarbons are those of the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6; R² is alkylcontaining from 1 to 4 carbon atoms and p is 0 to 18. Also,fluoro-substituted hydrocarbons may be of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, y is F orC_(n)F_(2n); b is at least 1, such as 2 to 10; m is 0 to 6 and p is 0 to18.

Preferred organo-silicon materials include halogenated siloxanes,halogenated alkoxysiloxanes such as perfluoroalkoxysiloxane (PFOSi),alkoxy halogenated alkoxysilanes, such as alkoxy-perfluoroalkoxysilane;alkoxyacetylacetonate halogenated polysiloxanes, such asalkoxyacetylacetonate-perfluoroalkoxysiloxane, alkoxy-alkylsilylhalides;polyalkylsiloxanes, such as polydimethylsiloxanes, andalkoxyacetylacetonate-polyalkylsiloxanes, such as alkoxyacetylacetonate(acac) polydimethylsiloxanes. Exemplary surface modifying treatmentagents include tantalum halide-perfluoroalkoxysiloxane, such asTaCl₅:PFOSi; tantalum alkoxy-perfluoroalkoxysilane; tantalumalkoxyacetylacetonate-perfluoroalkoxysiloxane, like Ta(EtO)₄acac:PFOSi;tantalum alkoxy-alkylsilylhalide; tantalum halide-polyalkylsiloxane,like TaCl₅:PDMS; niobium alkoxide-perfluoroalkoxysiloxane, such asNb(EtO)₅:PFOSi and Ta(EtO)₅:PFOSi; titaniumalkoxide-perfluoroalkoxysiloxane, like Ti(n-BuO)₄:PFOSi; zirconiumalkoxide-perfluoroalkoxysiloxane; lanthanumalkoxide-perfluoroalkoxysilane, like La(iPrO)₃:PFOSi; tungstenchloride-perfluoroalkoxysiloxane, like WCl₆:PFOSi; tantalumalkoxide-polyalkylsiloxane, like Ta(EtO)₅:PDMS; and tantalumalkoxyacetylacetonate-polyalkylsiloxane, like Ta(EtO)₄acac:PDMS.

In an embodiment, the fluorinated hydrocarbon is R_(f)—(CH₂)_(p)—X whereR_(f) is a perfluorinated hydrocarbon group including an oxygensubstituted hydrocarbon group, such as a perfluorinated alkyl group or aperfluorinated alkylene ether group and p is 0 to 18, preferably 0-4,and X is a polar group such as a is carboxyl, like of the structure—(C═O)—OR; and R is hydrogen, perfluoroalkyl, alkyl or substituted alkylcontaining from 1 to 50 carbon atoms.

Examples of perfluoroalkyl groups are those of the structureF—(CFY—CF₂)_(m) where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1to 6.

Examples of perfluoroalkylene ether groups are those of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, Y is F orC_(n)F_(2n); b is 2 to 20, m is 0 to 6, and p is 0 to 18, preferably 2to 4 and more preferably 2.

Preferred fluorinated materials are esters of perfluorinated alcoholssuch as the alcohols of the structure F—(CFY—CF₂)_(m)—CH₂—CH₂—OH where Yis F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6.

Further preferred as fluorinated hydrocarbons are perfluorinatedhydrocarbons of the structure R_(f)—(CH₂)_(p)—X where R_(f) is aperfluoroalkylene ether group or a perfluorinated alkyl group such asthose described above, p is an integer of from 0 to 18, preferably 0 to4, and X is a carboxyl group, preferably a carboxylic ester groupcontaining from 1 to 50, preferably from 2 to 20 carbon atoms in thealkyl group that is associated with the ester linkage.

Further preferred as fluorinated hydrocarbons are perfluorinatedhydrocarbons of the structure R_(f)—(CH₂)_(p)—Z where R_(f) and p are asdefined above, preferably R_(f) is a perfluoroalkylene ether group suchas those described above, and p is from 2 to 4, and Z is a phosphorusacid group. Examples of phosphorus acid groups are:

where R″ is a hydrocarbon or substituted hydrocarbon radical having upto 200, such as 1 to 30 and 6 to 20 carbons, R″ can also include theperfluoroalkyl groups mentioned above, and R′ is H, a metal such aspotassium or sodium or an amine or an aliphatic radical, for example,alkyl including substituted alkyl having 1 to 50 carbons, preferablylower alkyl having 1 to 4 carbons such as methyl or ethyl, or arylincluding substituted aryl having 6 to 50 carbons.

Preferably, the phosphorus acid is of formula II where R and R′ are H.

Suitable methods for preparing the surface modifying treatment agentswherein the organo portion of the metal containing organic ligand isreactive with the organo-silicon containing material or fluorinatedhydrocarbon group are disclosed in U.S. Pat. Nos. 7,879,437 and8,067,103. In one embodiment, for instance, the organo portion of theorganometallic compound may be selected from those groups that may bereactive with the acids (or their derivatives) of a perfluoroalkyleneether.

As an example, the surface modifying treatment agent could be preparedby mixing the metal containing organic ligand and the silicon-containingmaterial or fluorinated hydrocarbon in a closed system to avoidhydrolysis of the reactants. Reaction can occur neat or in the presenceof a non-reactive solvent such as chlorinated or fluorinated solvent,for example, methylene chloride. Heat may be used to initiate andcomplete the reaction. Solvent may be removed by evaporation and thereaction product can be redissolved in a suitable solvent such as analcohol, for example, ethanol or propanol, for application to thesubstrate. The mole ratio of the organosilicon-containing material tothe metal containing organic ligand is typically from 100:1 to 1:100,preferably from 1:1 to 10:1 depending on the valence of the metal of themetal containing organic ligand. For example, the molar ratio oforganosilicon compound to Ta(V) is typically 5 to 1.

In an embodiment, the surface modifying treatment agent may berepresented by the formula X_(a)(OR)_(b)M, wherein OR is a C₁ to C₁₈alkoxide, X is the hydrophobic tail represented by the organo-siliconmaterial or the fluorinated hydrocarbon, M is metal of the metalcontaining organic ligand and a+b equals the valency of M and furtherwherein neither a nor b are zero.

In an exemplary embodiment, the surface modifying agent may be formed byreacting an organosilicon compound such as an organosilane or apolysiloxane with a metal containing organic ligand, such as aderivatized alkoxide. The metal of the metal containing organic ligandis covalently bonded to the organosilicon compound to form the anchorand the hydrophobic tail.

An exemplary reaction scheme of the surface modifying treatment agent,X_(a)(OR)_(b)M, with a siliceous formation, —(—O—Si—O—Si—)_(n), may berepresented as:

X_(a)(OR)_(b)M+(—O—Si—O—Si)_(n)→X_(a)(OR)_(b-1)M-(O—Si—O—Si—)_(n)+R—OH.

The surface modifying treatment agents disclosed herein are effective inreducing frictional drag of a fluid within a hydrocarbon producingreservoir. The frictional drag may be created during the turbulent flowof fluids within the well. When bound to the surface of a substrate, thesurface modifying treatment agents disclosed herein reduce the slidingangle between the fluid and the substrate within the well. The reductionin sliding angle may be between hydrocarbons and a substrate treatedwith the surface modifying treatment agent. Further, the reduction insliding angle may be between water (aqueous phase) and a substratetreated with the surface modifying treatment agent. Fluid flowimprovement has been evident in both hydrocarbon and aqueous phases.

The reduction in frictional drag within the well is thus attributable tothe bonding of the surface modifying treatment agent onto the surface ofthe substrate. Thus, the modification of the substrate surface reducesdrag and provides improved flow of hydrocarbon (or water phase) from thewell. Productivity of the hydrocarbon producing well is thus enhanced byuse of the surface modifying treatment agents.

The surface modifying treatment agents disclosed herein are ofparticular value in the reduction of frictional drag during the pumpingof produced hydrocarbons from the hydrocarbon producing reservoir.

The reduction in sliding angle further is of benefit in enhancing loadrecovery of water by increasing the recovery of flowback water from thewell after a fracturing fluid has been returned to the surface.

As used herein, the sliding angle (also known as tilting angle) is ameasurement of the lateral adhesion of the drop to the substratesurface. Thus, the sliding angle of a fluid on a substrate having asurface modifying treatment agent bonded thereto is less than thesliding angle of the same fluid on the (same) substrate (“pristineunmodified substrate”) which does not have the surface modifyingtreatment agent bonded thereto. Where the surface modifying treatmentagent is bond only to a portion of the substrate, the sliding angle ofthe drop of fluid on the portion of the substrate having the surfacemodifying treatment agent bonded thereto is less than the sliding angleof the fluid on the substrate not having the surface modifying treatmentagent bonded thereto.

The reduction in frictional drag during the production of hydrocarbonsfrom the well is thus measured by a reduction in the sliding angle ofthe fluid with the formation surface. The reduction in adhesion bondstrength results in reduced drag between the liquid and the solidsurface, allowing for easier fluid flow at a given stress. The decreasein sliding angle accelerates the flow of fluid from the well bylessening the amount of fluid trapped within the formation.

In an embodiment, the sliding angle of a fluid to a substrate surfacetreated with the surface modifying treatment agent may be less than orequal to 60°; in some cases, less than or equal to 20°; in other cases,less than or equal to 10° and in some other cases, less than or equal to5°. In one instance, the sliding angle for hydrocarbons has beenobserved to be less than 10°. In another instance, the reduction inlateral adhesion of a fluid has been observed by a reduction in thesliding angle from 80° (non-treated substrate) to 40° (treatedsubstrate).

The reduction in sliding angle is independent of the contact angle. Thecontact angle refers to the angle between a drop of the liquid and thesurface of the substrate. A high contact angle reduces the normaladhesion of a liquid droplet to the solid surface due to a reduction ofthe liquid-solid contact area.

The contact angle is a measure of hydrophobicity. Typically, a liquid isconsidered to be “non-wet” or hydrophilic when the contact angle is lessthan 90° and “non-wetting” or hydrophobic when the contact angle isgreater than 90°. A surface having a water contact angle greater than150° is usually termed “ultra-hydrophobic” characterizing awater-repellant surface. A superhydrophobic surface may have a contactangle hysteresis less than 10°; in some cases, less than 5°. When thecontact angle is less than 90°, the wetting tendency of the surfacemodified substrate may greater when the substrate is rough versussmooth. When the contact angle is greater than 90°, the substrate mayrepel more when the substrate is rough.

Since hydrophobicity prevents the formation of water blocks on thesurface of the substrate, the contact angle is indicative of thecapillary pressure within the substrate. Whereas the contact angle isrepresentative of static conditions, the sliding angle is representativeof fluid movement downhole. No relationship can be drawn between thecontact angle and sliding angle. As such, the contact angle provides noindication of the sliding angle. Improvement in frictional drag has beenseen with a reduced sliding angle and a contact angle less than or equalto 20°. Further, improvements in frictional drag have been observed witha reduced sliding angle and a contact angle greater than or equal to120°. For instance, the effectiveness of surface modifying treatmentagents on substrate surfaces to reduce frictional drag has been seenwith fluids exhibiting a contact angle less than 20° and a sliding angleless than 20° and a contact angle greater than 120° and a sliding angleless than 20°.

The surface modifying treatment agents disclosed herein may furtheralter the surface energy of the formation being treated.

The attachment of the anchor of the surface modifying treatment agentonto the formation prevents spalling of fines and in-situ finesgeneration is minimized or stabilized. Spalling of fines may beprevented by altering the zeta potential of formation fines. Forinstance, where the surface modifying treatment agent contains ametallic anchor, by covalently attaching the metal-containing ligandonto the Si or Al surface, migration of fines into producing areas ofthe formation may be minimized.

The hydrophobic nature of the tail further alters the wettability of theformation surface. The self-assembled hydrophobic monolayer covalentlyattached to the formation surface lowers the water saturation andenhances recovery of water from the formation surface.

Particulates of a weakly consolidated, semi consolidated orunconsolidated formation may further be consolidated by use of thesurface modifying treatment agents disclosed herein. The bonding of theanchor of the treatment agent on the surface formation prevents orminimizes the influx of fluids into the formation. Aggregation of theparticulates results from the reduction in charge density.

Upon being pumped into the formation, the surface modifying treatmentagent may enter into the pore spaces of the formation. Multipleinteractions of molecules of the surface modifying treatment agent withformation particulates causes aggregation or agglomeration of formationparticulates. Further, it is believed, that the reactivity of thesurface modifying treatment agent with formation surfaces or portions offormation surfaces creates an aggregation or agglomeration of thehydrophobic tail in near proximity to the formation surface. The use ofthe surface modifying treatment agents as a means to consolidateparticulates of the formation is particularly effective in the treatmentof shale formations.

The consolidation further provides stability to the formation sinceaggregated particulates allow fluid to flow back through the pumpedfluids without flowing formation solids back to the surface. Thisphenomenon is attributable to the anchoring of the metal of the surfacemodifying treatment agent onto the surface formation and to thealignment of the tail of the treatment agent enabling limitedcontact-time of the fluid with formation surface.

In another embodiment, the swelling, dispersement, disintegration,migration and otherwise disruption of clay in oil and gas producingformations may be decreased by use of the surface modifying treatmentagent and native fluid production may dislodge fines in a pore throat.The degree of swelling, as well as migration of clay particles, is oftenincreased when formation clays are disturbed by foreign substances, suchas aqueous well treatment fluids. Like fines formation, the swelling andmigration of formation clays presents problems during stimulation andwell completion, such as by increasing the bulk volume of treatmentfluids. For instance, clays, in the presence of well treatment fluids,often expand and may be disrupted by becoming unconsolidated, therebyproducing particles which migrate into a borehole. The presence of thehydrophobic tail on the surface modifying treatment agent prevents theswelling and migration of formation clay particles. Thus, by obstructionof formation capillaries, swelling and migration of formation clay maybe reduced or prevented by the use of the surface modifying treatmentagent disclosed herein. Loss of formation permeability is thus minimizedto create little, if any, reduction in the flow rate of hydrocarbons.

In a preferred embodiment, the surface modifying treatment agent is usedin the treatment of a shale formation or a clay-rich formation in orderto coat the surface of the formation to reduce water absorption orimbibement of water in order to reduce swelling.

The presence of the hydrophobic tail of the surface modifying treatmentagent impedes the permeability of water in water saturated zones of aproducing formation without reducing relative permeability to oil orgas. Since relative permeability is dependent on the pore structure andsize, wettability of the formation surface and capillary pressure of thewater within the formation, in some instances, such as where theformation is characterized by larger pores, water and oil permeabilitymay be improved. With small pore surfaces, the hydrophobic tail of thesurface modifying treatment agent attached indirectly to the mineralsurface of the formation through the anchor is relatively non-damagingto oil permeability. For example, it is particularly effective in oilsaturated sandstone formations while exhibiting the ability to decreasewater permeability substantially in water saturated zones.

The surface modifying treatment agents disclosed herein may also be usedin the treatment of rich gas or retrograde condensate gas reservoirs andthus presents value to retrograde gas fields by increasing condensateproduction. In such reservoirs, heavy end fraction of gases may beprecipitated in liquid form from solution in the gas as the reservoirpressure within the well is decreased below the dew point of the gas.Condensed liquid drains downward by gravity when its saturation exceedsthe irreducible condensate saturation. With retrograde gases, liquidscannot be reabsorbed into the gas phase even if pressure is increased bya rate reduction. When a well treatment fluid containing the surfacemodifying treatment agent disclosed herein is pumped into a retrogradegas well, the permeability of the formation may be maintained, andcondensate dropout minimized. Thus, in turn, minimizes the possibilityof the formation of an emulsion between precipitated hydrocarbons andthe invading water from the aqueous based well treatment fluid. Thepressure below the dew point of the hydrocarbons may therefore bemaintained. By enhancing the permeability of the formation to liquidhydrocarbons, loss of light condensate liquids is minimized and lightcondensate liquids may therefore be more readily displaced.

The surface modifying treatment agents disclosed herein may also be usedto enhance load recovery of water. The presence of the hydrophobic tailon the surface modifying treatment agent provides increased recovery offlowback water from the well after fracturing fluid has been returned tothe surface. In some instances, flowback water may be as low as 25%,while in some cases, can be as high as 75%, of the volume of fluid thatwas injected into the well. This application is particularly useful inshale fractures having a complex of narrow fractures with limitedconductivity where a low range of fluid recovery values (30% or less)are typically experienced. This lack of recovery is often interpreted ascausing formation damage (from residual polymer gels residues),resulting in lowered gas/oil production. Methods as described in thisdisclosure that results in increased water recovered from the shale-typeformation can thus be interpreted to reduce formation damage, and henceimprove well productivity. For instance, in a typical fracturing job ona Marcellus shale formation, 20,000 to 150,000 barrels of fracturingfluid may be pumped into the well, depending upon the number of stagespumped.

The hydrophobic nature of the surface modifying treatment agent mayfurther serve to control water condensation in the pores of a nearwellbore region of a permeable formation. Often, the liquid zone formedfrom the condensation of hydrocarbons within a gas reservoir close tothe wellbore hampers gas flow, reducing the productivity of the well theformation of “water block” or “water bank” zones. Condensation of waterin the pores of a near wellbore region of a permeable formation may bedecreased by the presence of the surface modifying treatment agent.Fluid transfer and water flux through the pores of the near wellboreregion of the formation may be controlled by inhibiting the formation ofa water bank by the hydrophobic tail of the surface modifying treatmentagent.

The surface modifying treatment agent may further be used to enhance theproductivity of injection wells in a water flood operation. Field wateror field brine pumped through one or more injection wells drilled intothe formation causes displacement of oil within the formation andimprovement in hydrocarbon recovery. In an embodiment, one or moreinjection wells may be spaced apart from each other and perforated so asto be able to direct the injection fluid containing the surfacemodifying treatment agent in the direction of one or more producingwells and into the hydrocarbon-bearing formation. The presence of thehydrocarbon tail on the surface modifying treatment agent enhancesdirection of water flow within the matrix of the subterranean formation.As the injection fluid is pumped into the formation, the surfacemodifying treatment agent in the well treatment fluid cause the water tobe redirected through the formation. In so doing, hydrocarbons aredisplaced toward the producing well or wells. Thereafter, hydrocarbonswill be produced from the producing well to the surface.

The surface modifying treatment agent disclosed herein may further beused in the treatment of tar sand formations. Conventional recovery ofhydrocarbons from heavy oil deposits within the tar sand is generallyaccomplished by steam injection to lower the viscosity of the crude tothe point where it can be pushed toward the production wells. The heavyoil is immobile at reservoir temperatures and therefore the oil istypically heated to reduce its viscosity and mobilize the oil flow. Thesurface modifying treatment agent enhances oil flow and thus recovery ofoil from tar sand by minimizing the flow of water into the deposits. Thehydrophobicity of the surface modifying treatment agent furtherminimizes the interference of steam in the removal of oil from tar sanddeposits.

In another embodiment, the surface modifying treatment agent is used inan acidizing operation in order to increase the penetration of acid intothe formation. Since the hydrocarbon tail of the surface modifyingtreatment agent is either on or in close proximity to the formationface, reaction of acid with the formation surface is retarded. Thereactive acid may therefore etch the formation in more distant areasfrom the port of entry of the treatment fluid. Deeper acid penetrationin the well may therefore result.

Further, the surface modifying treatment agent may be used to shut-offwater into a formation. In this regard, the surface modifying treatmentagent finds particular applicability in the treatment of matrixformations having finer grained particles between larger rock particlesor finer grained particles in which the larger particles are embedded.The hydrophobic tail on the surface modifying treatment agent reducesthe influx of water into matrix formations characterized by lowpermeability. Further, matrix formations produce a large amount of waterdue to an influx of water into the wellbore. Over time, the amount orpercentage of produced water may increase resulting in a correspondingdecrease in the production of desired hydrocarbons, eventually renderingfurther production of hydrocarbons from the well uneconomical. Thehydrocarbon tail indirectly attached to the formation blocks the flow ofwater into the formation or otherwise abates the influx of water. Thisresults in increased rates in hydrocarbon production and ultimatelyincreases recoverable reserves.

In an embodiment, the surface modifying treatment agent may function asa passive anti-microbial agent in order to counter bacterial growthprincipally caused by nitrogen and/or phosphorus in formation water orwithin fluid injected into the formation. The hydrocarbon tail of thesurface modifying treatment agent repels the fluid from the formationand thus decreases contact time of the fluid in the formation. Thisprevents the build-up of aerobic bacteria, anaerobic bacteria and othermicrobials.

In another embodiment, the surface modifying treatment agent may be usedto passively inhibit, control, prevent or remove scale deposition ontoor within the formation. The hydrophobic tail of the surface modifyingtreatment agent minimizes or decreases the ability of such materials toadhere to the formation. This may be attributable to the hydrophobicnature of such minerals scales as calcium, barium, magnesium salts andthe like including barium sulfate, calcium sulfate, and calciumcarbonate scales. The composites may further have applicability in thetreatment of other inorganic scales, such as metal sulfide scales, likezinc sulfide, iron sulfide, etc. Since such scales tend to plug the porespaces and reduce the porosity and permeability of the formation, thesurface modifying treatment agent described herein improves thepermeability of the formation.

When coated onto the substrate of the formation being treatment, thebulky nature of the hydrocarbon tail of the surface modifying treatmentagent prevents or controls deposition of organic particulates onto theformation substrate, fines are returned to the surface with the fluid.In addition, bonding of the metal of the surface modifying treatmentagent onto the formation minimizes binding sites for such organicparticulates. Thus, the surface modifying treatment agents may be usedto control or prevent the deposition of organic materials (such asparaffins and/or asphaltenes) within or onto the formation. Such solidsand particulates are known to negatively impact the overall efficiencyof completion of wells and, like scale inhibitors, can precipitate fromproduced water and create blockages in flow paths within the formation.The formation and deposition of such unwanted contaminants decreasepermeability of the subterranean formation, reduce well productivity,and, in some cases, may completely block well tubing.

The surface modifying treatment agent may further be introduced into anon-hydrocarbon producing well in order to dispose of salt water. Thisapplication may be used in those instances where water floodingoperations are not in use. In this operation, the salt water may bedisposed of by injecting the water into permeable low pressure stratabelow the fresh water level in a salt water disposal well.

The bonding of a surface modifying treatment agent onto a subterraneanformation may be enhanced by first pre-treating the formation. In thepre-treatment, an aqueous fluid is first pumped into the well whichpenetrates the formation. The aqueous fluid preferably contains anorganic acid such as a weak organic acid, like acetic acid, formic acid,citric acid, oxalic acid, malonic acid, succinic acid, malic acid,tartaric acid, phthalic acid ethylenediaminetetraacetic acid (EDTA),nitrilotriacetic acid, glycolic acid,N-hydroxyethyl-N,N′,N′-ethylenediaminetriacetic acid,hydroxyethyliminodiacetic acid, diethylenetriaminepentaacetic acid,cyclohexylenediaminetetraacetic acid or a mixture thereof. In suchinstances, the amount of organic acid in the aqueous fluid is typicallybetween from about 0.5 to about 25 volume percent.

The aqueous well treatment fluid containing the surface modifyingtreatment agent is then pumped into the well. The access to the sitesfor the surface modifying treatment agent to bind onto the surface ofthe subterranean formation is facilitated by pre-treatment of thesubterranean formation with the aqueous fluid.

One or more stages of aqueous fluids may be pumped into the well priorto pumping of the aqueous well treatment containing the surfacemodifying treatment agent. Where more than one stage of aqueous fluid ispumped into the well prior to pumping of the aqueous well treatmentfluid containing the surface modifying treatment agent, each stage maycontain the same organic acid or a different organic acid. Thus, forexample, the first and second stages of aqueous fluids pumped into thewell may both contain acetic acid or the first stage may contain aceticacid and the second stage tartaric acid. Where more than two stages ofaqueous fluids are pumped into the well prior to pumping of the aqueouswell treatment fluid containing the surface modifying treatment agent,more than one or all of the stages may contain the same organic acid oreach stage may contain a different organic acid and so on.

Prior to pumping the aqueous fluid into the well or in between pumpingof different stages of aqueous fluids into the well, the surface of theformation may be further treated with an alkaline solution such assodium hydroxide or potassium hydroxide.

Where the formation is treated with a salt solution, the formation ispreferably treated with one or more subsequent stages of aqueous fluidprior to pumping of the surface modifying treatment agent into the well.The pumping of an alkaline solution into the well may be especiallydesirable in those formations composed of metal oxides in order toregenerate the binding sites for the surface modifying treatment agentonto the formation.

Preferred embodiments of the present disclosure thus offer advantagesover the prior art and are well adapted to carry out one or more of theobjects of this disclosure. However, the present disclosure does notrequire each of the components and acts described above and are in noway limited to the above-described embodiments or methods of operation.Any one or more of the above components, features and processes may beemployed in any suitable configuration without inclusion of other suchcomponents, features and processes. Moreover, the present disclosureincludes additional features, capabilities, functions, methods, uses andapplications that have not been specifically addressed herein but are,or will become, apparent from the description herein, the appendeddrawings and claims.

All percentages set forth in the Examples are given in terms of weightunits except as may otherwise be indicated.

EXAMPLES Example 1

Berea sandstone cores measuring 1.0″ in diameter and 1.5″ in length andhaving nitrogen permeability of 200 and were evacuated with air and thensaturated with either 2% aqueous solution of potassium chloride (KCl) orISOPAR™ paraffinic fluid of ExxonMobil Chemical Company. The core wasthen installed in a hydrostatic core holder apparatus. Approximately 200psi back pressure was applied at the exit end and approximately 1,000psi confining stress (overburden pressure) was applied around the entirecylinder. The confining stress pressure simulated stress in the downholeformation. When saturated with KCl, a flow of the paraffinic fluid wasflowed through the core in order to establish a base line permeabilityto the core to the oil followed by a flow of KCl solution to establish abaseline permeability to water. When saturated with the paraffinicfluid, a flow of the KCl solution was flowed through the core in orderto establish a base line permeability to the core to the water followedby a flow of paraffinic fluid to establish a baseline permeability tooil. Pressure drop was measured across the entire length of the core andwas used to calculate individual baseline permeability to water and tooil.

Example 2

A five pore volume of a neat fluid of AL-B, 2% of an organophosphonatehaving a hydrocarbon polymeric hydrophobic tail in an organic solventblend, commercially available from Aculon, Inc., was then injected intothe core and allowed to soak for about one hour. After treatment, oil isflowed first and a comparison of permeability to oil right aftertreatment versus permeability to oil before treatment was made. Afteroil, water was flowed measuring permeability of water at residual oilafter treatment and this was compared to the water right beforetreatment. As such, the oil at irreducible water saturation and thewater at residual oil saturation were measured and the percent retentionin permeability was then determined.

FIG. 4 illustrates the percent regain of the testing. While water regainpermeability was very high (in excess of 300% and 468%), oil regainpermeability was slightly exceeded 100% both Berea samples. FIG. 4establishes that treatment of the core with an organophosphonatetreatment agent containing a hydrophobic tail provides an improved rateof return of fluids from the well. The data demonstrates that theorganophosphonate treatment agent stabilizes fine movement sincedecreased permeability would be noted if movement of fines existed.Further, FIG. 4 illustrates that use of the organophosphonate treatmentagent would reduce solids flowback to the surface in light of theincrease in permeability. Further, the lack of reduced permeabilityevidences minimal clay swelling. Further, the ability to readily producewater by use of the organophosphonate treatment agent provides forminimal residence time for microbes, scales as well as organic depositssuch as asphaltenes. The increase in the capacity of the reservoir totransmit to transmit hydrocarbons illustrates enhancement in recovery ofhydrocarbons from deposits within tar sands. Further, the hydrophobiccoating of the formation with the organophosphonate further provides forinhibition in the reactivity of acid such that deeper penetration ofacid into the formation is possible.

Example 3

Permeability testing was performed on a synthetic core composed of 20-40mesh gravel, 100 mesh sand and 325 mesh silica. The 325 mesh silicamimics fines in formations. The synthetic core was 1.0″ in diameter and2.0″ in length and having nitrogen permeability of 100 and was saturatedwith 2% aqueous solution of potassium chloride (KCl). The core was theninstalled in a hydrostatic core holder apparatus. Approximately 200 psiback pressure was applied at the exit end and approximately 1,000 psiconfining stress (overburden pressure) was applied around the entirecylinder. The confining stress pressure simulated stress in the downholeformation. ISOPAR™ paraffinic fluid was then flowed through the core inorder to establish a base line permeability to the core to the oil. Whensaturated with the paraffinic fluid, a flow of the KCl solution wasflowed through the core. Pressure drop was measured across the entirelength of the core and was used to calculate individual baselinepermeability to water and to oil.

A five pore volume of a neat fluid of AL-B was then injected into thecore and allowed to soak for about one hour. After treatment, paraffinicfluid was flowed through the core and permeability of oil at irreduciblewater saturation was then measured and the percent retention inpermeability was then determined. After oil, water was flowed measuringpermeability of water at residual oil after treatment and this wascompared to the water right before treatment. As such, the oil atirreducible water saturation and the water at residual oil saturationwere measured and the percent retention in permeability was thendetermined.

The data is illustrated in FIG. 5 wherein the lack of reduction inpermeability demonstrates the lack of fines movement.

Example 4

The effect of surface modifying treatment agents on water andhydrocarbons was determined for three substrates. Each of the surfacemodifying treatment agents had a hydrophobic tail and an anchor. Theanchor through a covalent bond secures the surface modifying treatmentagent onto the surface of the substrate. The surface modifying treatmentagents were Hl-F and Aculon E [comprising 2% of a treatment agent havinga transition metal (anchor) linked to a fluorinated hydrocarbon tail inan organic solvent] and AL-B [comprising 2% of an organophosphonate(anchor) having a hydrocarbon polymeric hydrophobic tail in an organicsolvent blend]; all commercially available from Aculon, Inc. Aculon-Eand AL-B exhibited hydrophobic and oleophobic properties while Hl-Fexhibited hydrophobic properties only.

The surface modifying treatment agent was sprayed onto a glass slide(having a more homogeneous surface than natural rock), a core of Ohiosandstone and a core of Berea sandstone to provide a coatingapproximately 1 to 10 nm thick. The cores of Ohio sandstone and Bereasandstone were approximately 1.0″ in diameter and 1.5″ in length. Theanchor of the surface modifying treatment agent reacted with oxides onthe surface of the substrate. As a result, the surface modifyingtreatment agent was covalently bonded onto the surface of the substrate.The samples were then kept in an oven at 150 F until completely dry toremove the solvent. After being modified, all of the substrate surfaceswere hydrophobic. Contact angle and sliding (or roll-off) angle werethen determined and used as the primary measure of performance. Thecontact angle demonstrates wettability characteristics of the surfacewhile the sliding angle and contact angle hysteresis characterized theease of fluid roll off from the substrate.

Glass Slide.

Table I show the contact angles obtained with both water and ISOPAR-L™paraffinic fluid (Isopar-L simulated oil). As demonstrated, AL-B was themost oleophobic and the amount of hydrophobicity imparted by each of thethree surface modifying treatment agents was about the same. Glasstreated with Aculon E had a sliding angle of 20°, while modifiedsurfaces using Hl-F and AL-B exhibited a large contact angle hysteresiswith water. Drops of fluids stayed pinned on the surface even at a 90°rotation angle. The sliding angle using Isopar-L was 8 to 10° when Hl-Fwas used as the surface modifying treatment agent, 30° for AL-B andlittle roll off for Aculon E. In this last case, the hysteresis betweenadvancing (liquid drop front) and receding (rear end) angles was largeand the drop stay pinned on the surface of the modified glass. Thewettability behavior is set forth in Table I and demonstrates Aculon-Eto be more effective as surface modifying treatment agent to move waterwhile Hl-F was more effective in the flow of oil.

TABLE I Surface Modifier Contact Angle (Water) Contact Angle (IsoparL)None 36 Wetting state H1-F 95 10 E 83 48 AL-B 97 58

Ohio Sandstone.

The contact angle and sliding angle measurements for Ohio sandstone aredemonstrated in Table II below:

TABLE II Work of Surface Surface Energy Adhesion Sliding Angle ModifierFluid (mJ/m²) (mJ/m²) (°) H1-F Water  1.67 ± 0.01 11.10 ± 0.01 Pinningeffect H1-F IsoparL NA NA Goes through* E Water extremely low,  7.81 ±0.01 17-20 cannot be calculated E IsoparL 28.12 ± 0.02 58.20 ± 0.03 Goesthrough** AL-B Water  1.67 ± 0.01 11.10 ± 0.01 Pinning effect AL-BIsoparL 12.49 ± 0.04 37.34 ± 0.06 Goes through*** *surface modifiedglass had a very low sliding angle (7-10) **IsoparL drop stayed pinnedon E modified glass ***roll-off angle of IsoparL on AL-B modified glasswas 30°

In the case of Aculon Hl-F and AL-B, the contact angle was 147° and thesurface energy was 1.67 mJ/m². However, hysteresis between advancing andreceding angles in the range of 20 to 40° leading to a pinning effectand retention of the water drop even where the sample was rotated at90°. Adsorption studies also demonstrated that when the sandstone wastreated, water did not flow through the stone. After 30 minutes thewater drop was still on surface of the modified sandstone, while forcontrol Ohio Sandstone the water passed through instantaneously. WhenAculon E was used as the surface modifying treatment agent, the watercontact angle with the surface of the rock was 153°. The surface energywas very low. In this case, the interaction between the support andwater was less than that of the dispensing pipette tip and water. Thedrop had to be big enough so that its weight allowed it to be removedfrom the pipette tip. In this case, a sliding angle of 17-20° wasobserved. As the sample was left flat, water flowed more easily off thesurface of the rock with increase in drop size. No adsorption of thewater drop was left on the surface of the rock.

Oleophobicity of the surface treated with the surface modifyingtreatment agent was determined with Isopar-L. When the surface modifyingtreatment agent was Hl-F, Isopar-L was observed to go through thesurface instantaneously. The contact angle with AL-B modified sandstonewas 60°. The adsorption through the sandstone core was slower than inthe case of Hl-F but the core was observed to be very permeable toIsopar-L. The surface properties of modified sandstones are presented inTable II. (The surface energy and work of adhesion represent how easy itis to remove a drop of the fluid perpendicular to the surfaces while thesliding angle represents the ease of moving the fluid tangentially tothe surface and represents the movement of the fluid through a porousmedia.) The data shows similar conclusions as observed with modifiedglass slides, i.e., the movement of water was easier when the surfacemodifying treatment agent was Aculon E while Hl-F provided a better flowof hydrocarbons (due to low surface energy of the surface). It is likelythat a reduction in the roughness of the surfaces contributes to adecrease in drag and improved flow of hydrocarbon.

TABLE III Work of Surface Surface Energy Adhesion Modifier Fluid (mJ/m²)(mJ/m²) Sliding Angle (°) H1-F Water  1.67 ± 0.01 11.10 ± 0.01 Pinningeffect H1-F IsoparL NA NA Goes through* E Water extremely low,  7.81 ±0.01 17-20 cannot be calculated E IsoparL 28.12 ± 0.02 58.20 ± 0.03 Goesthrough** AL-B Water  1.67 ± 0.01 11.10 ± 0.01 Pinning effect IsoparL12.49 ± 0.04 37.34 ± 0.06 Goes through*** *surface modified glass had avery low roll-off angle (7-10°) **Isopar-L drop stayed pinned on Emodified glass ***sliding angle of Isopar-L on AL-B modified glass was30°

Berea Sandstone.

Berea sandstone showed the same hydrophobic behavior as the OhioSandstone. No contact angle could be measured using Isopar-L. For oil,the absorption was very quick. Absorption of AL-B was a little slowerthan Hl-F. The hydrophobic properties and surface energy results arepresented in Table IV where it is illustrated that surfaces modifiedwith Al—B and Hl-F exhibited low surface energy.

TABLE IV Average Surface Contact Modifier Angle Surface Energy Work ofAdhesion (mJ/m²) H1-F 122.83 10.15 33.33 AL-B 143.11 2.5 14.58As illustrated in Tables I, II, III and IV, substrate surfaces modifiedwith the described surface modifying treatment agents provide forimproved flow of produced hydrocarbons.

Example 5

Longevity studies were undertaken using glass slides and modified glassslides kept in brine (2% KCl, 11.6 ppg CaCl₂, 19.2 ppg ZnBr2, 12.5 ppgNaBr, 13 ppg CaBr₂/CaCl₂) for five months and sandstone kept in producedwater for one month. Atomic Force Microscopy (AFM) was used to determinethe smoothness of the surfaces. Several glasses slides were kept in thesame fluid and every month one slide was removed and analyzed. The slidewas then washed with deionized water and dried and then tested forhydrophobicity. Surfaces modified with Hl-F and Aculon E demonstratedgood stability in brine after five months. In the case of AL-B, adecrease in the contact angle through time was observed. In thefive-month period, the sliding angle for the Hl-F modified substratedecreased up to 4°.

Example 6

An effective method for depositing self-assembled monolayers from asurface modifying treatment agent onto an oxide surface was firstdetermined. The surface modifying treatment agent had a hydrophobic tailand an anchoring site. The anchoring site through a covalent bondsecured the surface modifying treatment agent onto the surface of thesubstrate. The surface modifying treatment agent exhibited hydrophobicproperties and was commercially available from Aculon, Inc. as Hl-F[comprising 2% of a treatment agent having a transition metal (anchor)linked to a fluorinated hydrocarbon tail in an organic solvent]. In thefirst test, Test A, a clean and dry glass slide was directly modifiedwith the monolayer by spraying the surface of the slide with Hl-F. Inthe second test, Test B, the surface of a glass slide was wet with athin film of water. Hl-F was then applied onto the coating. In the thirdtest, Test C, the surface of the glass slide was wet with a thin film ofISOPAR-L™ paraffinic fluid, a product of ExxonMobil Chemical Company.The ISOPAR-L simulated oil wet reservoirs. Hl-F was then applied ontothe slide.

After applying the nanocoating, each of the samples was then left forabout five minutes for the reaction to occur on the surfaces. Thesurface was then dried. A drop of water was then put onto the surface.If the drop spread on the surface then the quality of the bonding wasconcluded to be unacceptable. If the sample demonstrated hydrophobicity,then the coating was concluded to be successful. Test A demonstratedhydrophobicity while Test B and Text C did not. It was concluded thatthe glass slides were not modified successfully and did not enhance theability of the surface modifying treatment agent to adhere onto thesurface.

When Test B was repeated and the slide was kept exposed to air for aperiod of time in order for complete evaporation of the liquid to occur.HF-1 was then applied to the glass slide. The surface modified glass wasthen noted to exhibit hydrophobicity. No interaction of the oily surfaceof Test C was observed. It was concluded that binding efficiency of themonolayer would be very low when the surface of the rock being treatedwas exposed to oil or a large amount of water. It was further concludedthat the surface of the rock being treated would need to be dry andclean from organic material as well as other contaminants in order forthe surface modifying treatment agent to have the best access to thebinding site of the rock.

Example 7

Two Berea sandstone cores measuring 1.0″ in diameter and 1.5″ in lengthwere used. The first core had a nitrogen permeability of 804 md and thesecond core had a nitrogen permeability of 773 md. Both of the coresexhibited a porosity of about 20%. Both of the cores were evacuated withair and then saturated with either 2% aqueous solution of potassiumchloride (KCl) or ISOPAR™ paraffinic fluid. The cores were theninstalled in a hydrostatic core holder apparatus. Approximately 200 psiback pressure was applied at the exit end and approximately 1,000 psiconfining stress (overburden pressure) was applied around the entirecylinder. The confining stress pressure simulated stress in the downholeformation.

The first core was not subjected to a preflush but was saturated in oil.Initial permeability to oil and water was determined in the productiondirection. First the permeability to water at residual oil wasdetermined by flowing water through the core until differential pressurewas stabilized. Oil was then flowed through the core and thepermeability to oil was determined until there was irreducible water atstable differential pressure. The core was then treated with a surfacemodifying treatment agent exhibiting both hydrophobic and oleophobicproperties and commercially available from Aculon, Inc. as Aculon-E[comprising 2% of a treatment agent having a transition metal (anchor)linked to a fluorinated hydrocarbon tail in an organic solvent] in theinjection direction. Finally, permeability to oil and water wasre-established in the production direction. Both permeability to waterand oil cycles were repeated and determined. Then % regain permeabilitywas calculated.

The second core was preflushed by saturating it in 2% KCl. Initialpermeability to oil and water was determined in the productiondirection. Permeability to water at residual oil was first determined byflowing water through the core until differential pressure wasstabilized. Oil was then flowed through the core until irreducible waterwas established at stable differential pressure. Permeability was thendetermined. This was followed by an injection of 10 pore volume ofmethanol as the pre-flush flowed through the core. The sample was thentreated with the Aculon-E in the injection direction. Permeability tooil and water was then re-established in the production direction. Bothpermeability to water and oil cycles were repeated and determined. The %regain permeability was then calculated.

FIG. 6 shows the results obtained for regain permeability. Asillustrated, the water regain increased from 106% for the first core (nopre-flush) to 548% for the second core (pre-flush). This demonstratesbetter efficiency for bonding of the surface modifying treatment agentwhen the core is pre-flushed. The regain to oil remained essentiallysimilar with or without pre-flush.

In separate cores, a five pore volume of neat fluids of Hl-F and AculonE, 2% of treatment agents in an organic solvent, the treatment agentshaving a transition metal linked to a fluorinated hydrocarbon tail, andAL-A, 2% treatment agent in an organic solvent having a transition metallinked to a hydrophobic tail, all commercially available from Aculon,Inc., were then injected into their respective core and allowed to soakfor about one hour. After treatment, oil was flowed first and acomparison of permeability to oil right after treatment versuspermeability to oil before treatment was made. After oil, water wasflowed measuring permeability of water at residual oil after treatmentand this was compared to the water right before treatment. As such, theoil at irreducible water saturation and the water at residual oilsaturation were measured and the percent retention in permeability wasthen determined.

FIG. 7 illustrates the percent water regain and oil regain of thetesting for Hl-F and Aculon E. FIG. 7 illustrates oil regainpermeability to be slightly higher than water regain permeability. FIG.7 also illustrates the percent gas regain for AL-A to be in excess of100%. FIG. 7 establishes that treatment of the core with a treatmentagent having a metal linked to a hydrophobic tail provides an improvedrate of return of fluids from the well. The data further demonstratesthat the treatment agent stabilizes fine movement since decreasedpermeability would be noted if movement of fines existed. Further, FIG.7 illustrates that use of the treatment agent would reduce solidsflowback to the surface in light of the increase in permeability.Further, the lack of reduced permeability evidences minimal clayswelling. Further, the ability to readily produce water by use of thetreatment agent provides for minimal residence time for microbes, scalesas well as organic deposits such as asphaltenes. The increase in thecapacity of the reservoir to transmit to transmit hydrocarbonsillustrates enhancement in recovery of hydrocarbons from deposits withintar sands. Further, the hydrophobic coating of the formation with thetreatment agent further provides for inhibition in the reactivity ofacid such that deeper penetration of acid into the formation ispossible.

Example 8

About 5 g of clay containing 92 weight % silica (or quartz) and 8 weight% montmorillonite (simulating Wyoming drilling clay) was treated withHl-F fluid described in Example 1 and placed into an oven having atemperature of approximately 150° F. wherein the solvent was evaporated,leaving a coating of the treatment agent onto the clay. Untreated claywas also placed into an oven and heated under the same conditions.

Capillary suction time tests were performed by placing the clay samplesonto filter paper within a funnel and pouring water through the funnel.In separate examples, the water contained clay stabilizers—2 vol. % KCl,1 gpt ClayCare™ and 1 gpt Claytreat 3C™ (ClayCare and Claytreat areproducts of Baker Hughes Incorporated). In a comparative experiment,fresh water was poured through the funnel. Two electrodes were attachedto the filter paper. The amount of time between the water first touchingan electrode on the paper and the water reaching a second electrode onthe paper was then measured.

FIG. 8 illustrates the amount of time for fresh water to reach thesecond electrode as being almost six times less when the sand wastreated with Hl-F than not treated with Hl-F. This time furtherdecreased when the water contained clay stabilizers—KCl, ClayCare andClaytreat 3C. The data demonstrates that clay treated with Hl-F inhibitsthe swelling of clay.

Example 9

Permeability testing was performed on synthetic cores composed of 20-40mesh gravel, 100 mesh sand and 325 mesh silica. The 325 mesh silicamimics fines in formations. The synthetic cores were 1.0″ in diameterand 2.0″ in length and having nitrogen permeability of 100 and wassaturated with 2% aqueous solution of potassium chloride (KCl). Thecores were then installed in a hydrostatic core holder apparatus.Approximately 200 psi back pressure was applied at the exit end andapproximately 1,000 psi confining stress (overburden pressure) wasapplied around the entire cylinder. The confining stress pressuresimulates stress in the downhole formation. ISOPAR™ paraffinic fluid wasthen flowed through the cores in order to establish a base linepermeability to the cores to the oil. When saturated with the paraffinicfluid, a flow of the KCl solution was flowed through the cores. Pressuredrop was measured across the entire length of the cores and was used tocalculate individual baseline permeability to water and to oil.

Into separate cores were injected a five pore volume of a neat fluid ofHl-F, Aculon E and AL-A and the fluids were allowed to soak for aboutone hour. After treatment, paraffinic fluid was flowed through each ofthe cores and permeability of oil at irreducible water saturation wasthen measured and the percent retention in permeability was thendetermined. After oil, water was flowed measuring permeability of waterat residual oil after treatment and this was compared to the water rightbefore treatment. As such, the oil at irreducible water saturation andthe water at residual oil saturation were measured and the percentretention in permeability was then determined.

The data is illustrated in FIG. 9 wherein the lack of reduction inpermeability demonstrates the lack of fines movement.

Example 10

This Example illustrates the compatibility of HF-1 with acetic acid.Solutions containing 0.02% (by volume) HF-1 were prepared in thepresence 5%, 10% and 15% (by vols.) of acetic acid. Periodically, theHF-1/acetic acid mixtures were applied onto untreated glass slides, andthe contact angles of the slides were measured to determine if HF-1 wasstill active. Acetic acid and HF-1 were seen to be compatible at bothroom temperature and at 150° F. A contact angle of greater than 40° wasstill maintained after approximately 8 hours. Further, no precipitationwas formed when HF-1 was mixed with acetic acid, immediately or after 24hours at 75° F. In contrast, a gelatinous precipitate is observed ifHF-1 is added to an aqueous solution without acetic acid. The presenceof acetic acid kept HF-1 in solution.

Example 11

The performance of acetic acid in HF-1 was tested by measuring itscontact angle, with an oil contact angle of 100°. Two separate testswere performed and a small volume from each phase within each mixturewas applied to the glass slide and the contact angle was measured. Forthe first test, 45 ml water and 5 ml 2% (by vol.) HF-1 were mixed. Forthe second test, 5 ml 2% (by vol.) HF-1 was mixed with 45 ml water and 5ml glacial acetic acid. The contact angle of the glass slide wasmeasured after the oil phase, the interphase and the water phase of themixture was applied. FIG. 11 and FIG. 12 shows the contact angle for thefirst and second tests, respectively. HF-1 was seen to be still activeafter mixing in the oil phase for both cases with the acetic acidsolution sample maintaining a higher contact angle, while the baselinesample with only water has lower contact angle indicating chemicaldegradation. The performance of HF-1 chemically degraded in theinterphase for the case with water as well, but not the samplecontaining acetic acid. This is indicated by a higher contact angle(˜100°). The active ingredient is clearly not present in the aqueousphase for both cases.

Example 11

The initial oil permeability, KoSwi, of a carbonate free Bereastandstone core plug defined in Example 1 using ISOPAR-L™ paraffinicfluid was determined to be 98.3 mD. A 10 pore volume of a fluidcontaining 3 gpt Hl-F in BioBase 365 (a biodegradable synthetic oil ofolefins, available from Shrieve Chemical Products of The Woodlands,Tex.) was injected into the core. The core was then shut-in at 150° F.and the fluid was allowed to soak for about 2 hours. This was followedby introducing into the core 10 pore volumes of a 10% acetic acidsolution. ISOPAR-L was then flowed through the core. The final oilpermeability was observed to be approximately 138%. This indicates noadverse effect was observed by the acid treatment.

While exemplary embodiments of the disclosure have been shown anddescribed, many variations, modifications and/or changes of the system,apparatus and methods of the present disclosure, such as in thecomponents, details of construction and operation, arrangement of partsand/or methods of use, are possible, contemplated by the patentapplicant(s), within the scope of the appended claims, and may be madeand used by one of ordinary skill in the art without departing from thespirit or teachings of the disclosure and scope of appended claims.Thus, all matter herein set forth or shown in the accompanying drawingsshould be interpreted as illustrative, and the scope of the disclosureand the appended claims should not be limited to the embodimentsdescribed and shown herein.

What is claimed is:
 1. A method of treating a metal (M) oxide-containingsubterranean formation penetrated by a well comprising: (a) preparing anaqueous treatment fluid comprising: (i) a surface modifying treatmentagent having an anchor and a hydrophobic tail; and (ii) an aqueous mediacomprising an organic acid; (b) pumping the aqueous treatment fluid intoa well penetrating the subterranean formation; and (c) binding thesurface modifying treatment agent to a surface of the subterraneanformation by attaching the anchor to the formation.
 2. The method ofclaim 1, wherein the amount of organic acid in the aqueous media isbetween from about 0.5 to about 25 volume percent.
 3. The method ofclaim 1, wherein the aqueous treatment fluid is prepared on the fly. 4.A method of treating a metal (M) oxide-containing subterranean formationpenetrated by a well comprising: (a) pumping into the well an aqueoustreatment fluid comprising a surface modifying treatment agent and anaqueous media comprising an organic acid wherein the surface modifyingtreatment agent comprises an anchor and a hydrophobic tail attached tothe anchor; and (b) binding the surface modifying treatment agent to asurface of the subterranean formation by attaching the anchor to theformation.
 5. The method of claim 4, wherein the organic acid of theaqueous media is selected from the group consisting of acetic acid,formic acid, citric acid, oxalic acid, malonic acid, succinic acid,malic acid, tartaric acid, phthalic acid ethylenediaminetetraacetic acid(EDTA), nitrilotriacetic acid, glycolic acid,N-hydroxyethyl-N,N′,N′-ethylenediaminetriacetic acid,hydroxyethyliminodiacetic acid, diethylenetriaminepentaacetic acid,cyclohexylenediaminetetraacetic acid and mixtures thereof.
 6. The methodof claim 5, wherein the organic acid of the aqueous media is selectedfrom the group consisting of acetic acid, formic acid, citric acid andmixtures thereof.
 7. The method of claim 4, wherein the anchor is ametal and the hydrophobic tail is an organo-silicon material, afluorinated hydrocarbon or both an organo-silicon material and afluorinated hydrocarbon.
 8. The method of claim 4, wherein the anchor isan organophosphorus acid derivative.
 9. The method of claim 8, whereinthe anchor of the surface modifying treatment agent originates from anorganophosphoric acid, organophosphonic acid or an organophosphinicacid.
 10. The method of claim 9, wherein the organophosphorus acidderivative is at least one member selected from the group consisting of:(a) a derivative of a phosphoric acid having the structure(RO)_(x)—P(O)—(OR′)_(y); (b) a derivative of a phosphonic acid of thestructure:

and (c) a derivative of a phosphinic acid of the structure:

wherein: R and R″ are each independently a radical having a total of 1to 30 carbon atoms; R′ is H, a metal or a lower alkyl having from 1 to 4carbon atoms; x is 1 to 2; y is 1 to 2; x+y=3; a is 0-1; b is 1; c is1-2; a+b+c is 3; d is 0-2; e is 0-2; f is 1; and d+e+f.
 11. The methodof claim 1, wherein the surface modifying treatment agent is of theformula:R_(f)—(CH₂)_(p)—Z wherein: R_(f) is a perfluorinated alkyl group or aperfluorinated alkylene ether group; p is 2 to 4; and Z is selected fromthe group consisting of:

wherein R and R″ are a hydrocarbon or substituted hydrocarbon radicalhaving up to 200 carbon atom or a perfluoroalkyl group, and R′ is H, ametal, an amine or an aliphatic or aryl radical aryl.
 12. The method ofclaim 11, wherein R″ is aliphatic or aromatic substituent substitutedwith a perfluorinated alkyl group or a perfluorinated alkylene ethergroup.
 13. The method of claim 12, wherein the perfluoroalkylene ethergroup of R_(f) is of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 20; Y is H,F, C_(n)H_(2n+1) or C_(n)F_(2n+1); b is at least 1; m is 0 to 50; p is 1to 20; and X is H, F or an acid group or an acid derivative.
 14. Themethod of claim 11, wherein the perfluorinated alkyl group is of thestructure:

where Y is F or C_(n)F_(2n+1) and m is 4 to
 20. 15. The method of claim11, wherein the surface modifying treatment agent is selected from thegroup consisting of CF₃(C_(n)F_(2n))CH₂CH₂PO₃H₂ where n is between 3 and5, and CF₃(CF₂)_(x)O(CF₂CF₂)_(y)—CH₂CH₂—PO₃H₂ where x is from 0 to 7, yis from 1 to 20 and x+y is less than or equal to
 27. 16. The method ofclaim 11, wherein R or R′ contains a terminal or omega functionalgroups.
 17. The method of claim 16, wherein the terminal or omegafunctional group is selected from the group consisting of carboxyl,hydroxyl, amino, imino, amido, thio, cyano, sulfonate, carbonate,phosphonic acid or a mixture thereof.
 18. The method of claim 9, whereinthe organophosphoric acid, organophosphonic acid or organophosphinicacid is selected from the group consisting of amino trismethylenephosphonic acid, aminobenzylphosphonic acid, 3-amino propyl phosphonicacid, O-aminophenyl phosphonic acid, 4-methoxyphenyl phosphonic acid,aminophenylphosphonic acid, aminophosphonobutyric acid,aminopropylphosphonic acid, benzhydrylphosphonic acid, benzylphosphonicacid, butylphosphonic acid, carboxyethylphosphonic acid,diphenylphosphinic acid, dodecylphosphonic acid, ethylidenediphosphonicacid, heptadecylphosphonic acid, methylbenzylphosphonic acid,naphthylmethylphosphonic acid, octadecylphosphonic acid, octylphosphonicacid, pentylphosphonic acid, phenylphosphinic acid, phenylphosphonicacid, bis-(perfluoroheptyl) phosphinic acid, perfluorohexyl phosphonicacid, styrene phosphonic acid, and dodecyl bis-1,12-phosphonic acid. 19.The method of 7, wherein the metal of the anchor is a Group 3, 4, 5, or6 metal.
 20. The method of claim 19, wherein the metal of the surfacemodifying treatment agent is selected from the group consisting of Ti,Zr, La, Hf, Ta, W and Nb.
 21. The method of claim 7, wherein thehydrophobic organo-silicon material has a formula selected from:R¹ _(4-x)SiA_(x) and (R¹ ₃Si)_(y)B or an organo(poly)siloxane ororgano(poly)silazane of the formula:

where: R¹ are identical or different and are a hydrocarbon orsubstituted hydrocarbon radical containing from 1 to 100 carbon atoms; Ais hydrogen, halogen, OH, OR² or

B is NR³ _(3-y); R² is a hydrocarbon or substituted hydrocarbon radicalcontaining from 1 to 12 carbon atoms; R³ is hydrogen or R¹; x is 1, 2 or3; and y is 1 or
 2. 22. The method of claim 7, wherein the hydrophobicorgano-silicon material is of the formulaR¹ _(4-x)SiA_(x) wherein R¹ is a fluoro-substituted hydrocarbon and A isOR².
 23. The method of claim 7, wherein the fluorinated hydrocarbon isof the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6; R² is alkylcontaining from 1 to 4 carbon atoms and p is 0 to
 18. 24. The method ofclaim 21, wherein R¹ is of the structure:

where Y is F or C_(n)F_(2n+1); m is 4 to 20 and n is 1 to 6; R² is alkylcontaining from 1 to 4 carbon atoms and p is 0 to
 18. 25. The method ofclaim 7, wherein the fluorinated hydrocarbon is of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, y is F orC_(n)F_(2n); b is at least 1; m is 0 to 6 and p is 0 to
 18. 26. Themethod of claim 7, wherein the hydrophobic organo-silicon material is anorgano(poly)siloxane or an organo(poly)silazane.
 27. The method of claim26, wherein the organo(poly)siloxane or an organo(poly)silazane haveunits of the formula:

where R¹ are identical or different and are a hydrocarbon or substitutedhydrocarbon radical containing from about 1 to about 12 carbon atoms;and R³ is hydrogen or R¹.
 28. The method of claim 7, wherein thehydrophobic organo-silicon material contains additional units of theformula: R⁵ ₂SiO₂ where R⁵ is halogen.
 29. A method of treating asiliceous or metal (M) oxide-containing subterranean formationpenetrated by a well comprising: (c) pumping into the well an aqueoustreatment fluid comprising a surface modifying treatment agent and anaqueous media comprising an organic acid wherein the surface modifyingtreatment agent comprises an anchor and a hydrophobic tail attached tothe anchor; (d) binding the surface modifying treatment agent to asurface of the subterranean formation by attaching the anchor to theformation; and (e) aligning the surface modifying treatment agent to thesiliceous or metal oxide-containing subterranean formation such that thehydrophobic tail is directed away from the surface of the formation.